The production of hydrogen by the steam reforming of hydrocarbons is well known. In the basic process, a hydrocarbon, or a mixture of hydrocarbons, is initially treated to remove, or convert and then remove, trace contaminants, such as sulfur and olefins, which would adversely affect the reformer and the down stream water gas shift unit catalyst. Natural gas containing predominantly methane is a preferred starting material since it has a higher proportion of hydrogen than other hydrocarbons. However, light hydrocarbons or refinery off gases containing hydrocarbons, or refinery streams such as LPG, naphtha hydrocarbons or others readily available light feeds might be utilized as well.
The pretreated hydrocarbon feed stream is typically at a pressure of about 200 to 400 psig, and combined with high pressure steam, which is at a higher than the feed stream pressure, before entering the reformer furnace. The amount of steam added is much in excess of the stoichiometric amount. The reformer itself conventionally contains tubes packed with catalyst through which the steam/hydrocarbon mixture passes. An elevated temperature, e.g. about 1580° F., or 860° C., is maintained to drive the endothermic reaction.
The effluent from the reformer furnace is principally hydrogen, carbon monoxide, carbon dioxide, water vapor, and methane in proportion close to equilibrium amounts at the furnace temperature and pressure. The effluent is conventionally introduced into a one- or two-stage water gas shift reactor to form additional hydrogen and carbon dioxide. The shift reactor converts the carbon monoxide to carbon dioxide by reaction with water vapor, which generates additional Hydrogen. This reaction is endothermic. The combination of steam reformer and water gas shift converter is well known to those of ordinary skill in the art.
If CO2 capture from the high pressure syngas stream exiting the water gas shift unit is desired, the shift converter effluent, which comprises hydrogen, carbon dioxide and water with minor quantities of methane and carbon monoxide is introduced into a conventional absorption unit for carbon dioxide removal. Such a unit operates on the well-known amine wash or Benfield processes wherein carbon dioxide is removed from the effluent by dissolution in an absorbent solution, i.e. an amine solution or potassium carbonate solution, respectively. Conventionally, such units can remove up to 99 percent or higher of the carbon dioxide in the shift converter effluent.
The effluent from the carbon dioxide absorption unit is introduced into a pressure swing adsorption (PSA) unit. PSA is a well-known process for separating essentially pure hydrogen from the mixture of gases as a result of the difference in the degree of adsorption among them on a particulate adsorbent retained in a stationary bed.
Conventionally, the remainder of the PSA unit feed components, after recovery of pure hydrogen product, which comprises carbon monoxide, the hydrocarbon, i.e. methane, hydrogen and carbon dioxide, is returned to the steam reformer furnace and combusted to obtain energy for use therein
To practice CO2 emissions capture from such hydrogen plants, one must consider total emissions resulting from the plant, which includes CO2 recovery from reformer furnace flue gas as well.
The CO2 emissions from a steam reformer based conventional hydrogen plant originate from the reformer furnace flue gas. The root source of this total CO2 in the furnace flue gas results from two sources:                (a) the reaction within the reformer tubes and shift; and        (b) the combustion of fuel in reformer furnace.        
Each source contributes between about 40 and about 60% of the total CO2 emitted through the reformer furnace flue gas. For CO2 capture, conventional schemes employed consist of:                (a) removal of CO2, only from the high pressure syngas stream exit shift unit;        (b) removal of CO2, only from the reformer furnace flue gas; and        (c) removal of CO2 via both (a) and (b) above.        
Option (a) permits about 50 to about 60% of total CO2 emissions capture. Option (b) permits about 90% of total CO2 emissions capture. Option (c) permits about 95% of the total CO2 emissions capture. Option (a) permits only partial capture at reasonable cost, Option (b) is considered the most expensive of the three options, capital and utility requirements wise. Option (c) is also expensive, utility intensive and quite elaborate.
Therefore, it is very desirable and cost effective to have a H2 plant design that results in between about 85% and about 95%+ of total CO2 capture, solely from the high pressure syngas stream exit water gas shift reactor.